Methods, Treatment Fluids And Systems For Differential Acidizing Of A Siliceous Material

ABSTRACT

The rapid reaction of hydrofluoric acid with siliceous materials can make it difficult to increase the permeability of subterranean formations containing siliceous minerals. Methods for stimulating a subterranean formation can comprise: providing a latent hydrofluoric acid composition comprising a degradable matrix, and a hydrofluoric acid precursor dispersed in the degradable matrix; introducing a first treatment fluid containing the latent hydrofluoric acid composition in a non-dissolved form into a wellbore penetrating a subterranean formation comprising a siliceous material; differentially depositing the latent hydrofluoric acid composition upon a portion of the siliceous material in one or more locations; degrading at least a portion of the degradable matrix, thereby exposing at least a portion of the hydrofluoric acid precursor; converting the exposed hydrofluoric acid precursor into hydrofluoric acid; and reacting the hydrofluoric acid with the siliceous material where the latent hydrofluoric acid composition was deposited.

BACKGROUND

The present disclosure generally relates to subterranean stimulationoperations and, more specifically, to treatment fluids and methods foracidizing a siliceous material.

Treatment fluids can be used in a variety of subterranean treatmentoperations. Such treatment operations can include, without limitation,drilling operations, stimulation operations, production operations,remediation operations, sand control treatments, and the like. As usedherein, the terms “treat,” “treatment,” “treating,” and grammaticalequivalents thereof will refer to any subterranean operation that uses afluid in conjunction with achieving a desired function and/or for adesired purpose. Use of these terms does not imply any particular actionby the treatment fluid or a component thereof, unless otherwisespecified herein. More specific examples of illustrative treatmentoperations can include, for example, drilling operations, fracturingoperations, gravel packing operations, acidizing operations, scaledissolution and removal operations, sand control operations,consolidation operations, and the like.

Acidizing operations may be used to stimulate a subterranean formationto increase production of a hydrocarbon resource therefrom. During anacidizing operation, an acid-soluble material in the formation matrixcan be dissolved by one or more acids to expand existing flow pathwaysin the subterranean formation or to create new flow pathways in thesubterranean formation. Acid-soluble precipitation damage (i.e., scale)may be removed from the subterranean environment in a related manner.Illustrative substances within the formation matrix that may bedissolved by an acid include, but are not limited to, carbonatematerials, siliceous materials, ferrous or ferric materials, or anycombination thereof. Introduction of an acidizing fluid to asubterranean formation may take place at matrix flow rates withoutfracturing of the formation matrix, or at higher injection rates andpressures to fracture the formation matrix (i.e., an acid-fracturingoperation).

Carbonate formations can contain minerals, such as calcite or dolomite,which comprise a carbonate anion and a metal counter ion. When acidizinga carbonate formation, the acidity of a treatment fluid alone can oftenbe sufficient to consume the carbonate anion and thereby affectdissolution of the carbonate mineral. Both mineral acids (e.g.,hydrochloric acid) and organic acids (e.g., acetic acid and formic acid)can be used to acidize a carbonate formation, often with relativelysimilar degrees of success. The reaction of such acids with carbonateminerals can generate wormholes and other permeability-enhancingfeatures in the formation matrix. The heterogeneous lithology ofcarbonate formations can also facilitate the generation of suchpermeability-enhancing features during an acidizing operation, such asthrough differential etching and uneven surface dissolution. Theincreased formation permeability may improve production of a hydrocarbonresource from the formation.

Siliceous formations can include minerals such as, for example,zeolites, clays, and feldspars. As used herein, the term “siliceous”will refer to any substance having the characteristics of silica,including silicates and/or aluminosilicates. The mineral acids andorganic acids that are usually effective for dissolving carbonateminerals are generally ineffective for affecting dissolution ofsiliceous minerals. In contrast, hydrofluoric acid, another mineralacid, can react very rapidly with siliceous materials to promote theirdissolution. Additional mineral acids or organic acids may be used incombination with hydrofluoric acid in order to maintain a low pH stateas the hydrofluoric acid spends upon reacting with the siliceousmaterial. Unlike the case of carbonate mineral-acidizing operations, therapid reaction rate of hydrofluoric acid with siliceous minerals candiscourage differential etching to form wormhole-like structures andother permeability-enhancing features within the formation matrix.Instead, uniform etching in the near-wellbore area often occurs whenacidizing a siliceous mineral by conventional techniques, and thestimulation effect is relatively minimal. In addition, many siliceous,sedimentary minerals, such as shale, sandstone and mudstone, can havelow native permeability values that may further discourage deeppenetration of an acidizing fluid into the formation matrix. In theseand many other unconventional reservoirs, native permeability values maybe below about 0.1 millidarcy, often residing in the nanodarcy range,thereby making these reservoirs highly impermeable to fluid flow. When asiliceous formation is unable to be effectively stimulated through anacidizing operation, more costly and technically complex fracturingoperations may be needed for effective stimulation to be realized.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to one having ordinary skill in the art and the benefit of thisdisclosure.

FIG. 1 shows an illustrative schematic of a system that can delivertreatment fluids of the present disclosure to a downhole location,according to one or more embodiments.

FIG. 2 shows an image of a latent hydrofluoric acid compositiondeposited in a pattern on a split core.

FIG. 3 shows an illustrative profilometry plot following differentialetching of a split core.

DETAILED DESCRIPTION

The present disclosure generally relates to subterranean stimulationoperations and, more specifically, to treatment fluids and methods foracidizing a siliceous material.

One or more illustrative embodiments incorporating the features of thepresent disclosure are presented herein. Not all features of a physicalimplementation are necessarily described or shown in this applicationfor the sake of clarity. It is to be understood that in the developmentof a physical implementation incorporating the embodiments of thepresent disclosure, numerous implementation-specific decisions may bemade to achieve the developer's goals, such as compliance withsystem-related, business-related, government-related and otherconstraints, which may vary by implementation and from time to time.While a developer's efforts might be time-consuming, such efforts wouldbe, nevertheless, a routine undertaking for one having ordinary skill inthe art and the benefit of this disclosure.

As discussed above, the rapid reaction rate of siliceous minerals withhydrofluoric acid can make it very difficult to introducepermeability-enhancing features to these substances under typicalacidizing conditions, both at matrix flow rates and at injection ratesand pressures exceeding the fracture gradient. Due to the rapid reactionrate, dissolution may be confined to the near-wellbore area andstimulation may be precluded at locations further removed from thewellbore. The frequent low permeability and relatively homogeneouscharacter of siliceous minerals may also be problematic in this regard.

Lowering the reaction rate of a siliceous material with hydrofluoricacid might facilitate, in principle, the generation ofpermeability-enhancing features similar to those observed duringacidizing or fracture acidizing of a carbonate material. However, thepoor stimulation of siliceous materials under typical acidizingconditions is a function of more than just their rapid reaction rate;the low native permeability, such as that present in unconventionalreservoirs, and relative homogeneity of many siliceous materials may bejust as problematic toward increasing the permeability of a formationmatrix during an acidizing operation. Although hydrofluoric acidprecursors may be used to generate hydrofluoric acid in situ and therebyslow the dissolution rate of siliceous materials based largely on thekinetics of hydrofluoric acid production, they, by themselves, may dolittle to overcome the native lithology of many siliceous materials.Accordingly, hydrofluoric acid precursors would still be expected toaffect uniform dissolution at a point of contact with a siliceousmaterial in conventional acidizing operations, albeit at a decreasedreaction rate that is primarily limited by the kinetics of hydrofluoricacid production. Furthermore, the high solubility of many hydrofluoricacid precursors under typical acidizing conditions can make localizationof the precursor upon a desired portion of the siliceous materialdifficult due to fluid convection and dilution processes.

To address the foregoing issues, the present inventors discovered faciletechniques whereby a hydrofluoric acid precursor may be localized upon aportion of a siliceous material. Once the hydrofluoric acid precursorhas been localized, it may be decomposed to hydrofluoric acid and affectdifferential dissolution of the siliceous material. The differentialdissolution of the siliceous material may increase its permeability,similar to that seen during acidizing of a carbonate material.

Specifically, the present inventors discovered that a hydrofluoric acidprecursor may be protected within a degradable matrix to form a latenthydrofluoric acid composition that is neutrally or positively buoyant.Following its assembly, the latent hydrofluoric acid composition may bedifferentially deposited from a treatment fluid upon a portion of asiliceous material without a substantial reaction occurring duringdeposition. In addition to its feature of neutral or positive buoyancy,the latent hydrofluoric acid composition may be formulated to remain ina non-dissolved or solid form in a treatment fluid, thereby allowingdifferential deposition upon a siliceous material to take place throughdiffusive effects without substantial dilution occurring. Withoutprotecting the hydrofluoric acid precursor within the degradable matrixof the latent hydrofluoric acid composition (e.g., by forming a full orpartial coating upon the hydrofluoric acid precursor), such depositionconditions would ordinarily be expected to produce hydrofluoric acidrapidly and thwart any attempts at achieving differential deposition, asdiscussed above. Afterward or concurrently with differential depositionof the latent hydrofluoric acid composition, the degradable matrix maythen undergo degradation to expose at least a portion of thehydrofluoric acid precursor to reactive conditions, and the exposedhydrofluoric acid precursor may then convert into hydrofluoric acid. Thedegradation of the degradable matrix may be induced by a degradant, suchas an acid, or occur passively. Due to the localized manner in which thehydrofluoric acid precursor is deposited, coupled with the highreactivity of the generated hydrofluoric acid toward the siliceousmaterial, differential dissolution of the siliceous material may berealized at a location where the latent hydrofluoric acid composition isdeposited compared to where it is not. More effective stimulation of thesiliceous material may occur than through a uniform dissolution process.

In more particular embodiments, the inventors discovered that the latenthydrofluoric acid composition may be localized within a fracture networkdefined within the siliceous material. As used herein, the term“fracture network” will refer to a series of interconnected conduitswithin a subterranean matrix material that are collectively in fluidcommunication with a wellbore. The interconnected conduits will also bereferred to herein as “fractures.” Fractures within a subterraneanmatrix material may be naturally occurring, or they may be manmade.Manmade fractures may be created de novo, or naturally occurringfractures may be extended or expanded by introducing a fluid to awellbore at or above a fracture gradient pressure of the subterraneanmatrix material.

More specifically, the inventors discovered that by depositing thelatent hydrofluoric acid composition within a fracture network at orabove the fracture gradient pressure and subsequently generatinghydrofluoric acid therein, the hydrofluoric acid may penetratesignificantly further into the formation matrix than in conventionalnear-wellbore acidizing operations. Once the hydraulic fracturingpressure is released, the fractures can contract from theirfracturing-expanded state, thereby effectively trapping the latenthydrofluoric acid composition and localizing it away from thenear-wellbore area. This may allow much more effective stimulation to berealized by confining the dissolution process within the fracturenetwork and affecting differential dissolution of the siliceous materialas a whole. The fractures in which the latent hydrofluoric acidcomposition becomes localized may be previously existing fractures,fractures generated de novo during introduction of the latenthydrofluoric acid composition, or any combination thereof.

In addition to promoting more effective stimulation of siliceousmaterials, the latent hydrofluoric acid compositions and related methodsof the present disclosure may provide further advantages as well. Froman operational standpoint, keeping the hydrofluoric acid in latent formmay avert the handling and safety issues associated with direct use ofthis acid. Surface corrosion issues may similarly be avoided. In termsof the hydrofluoric acid precursor itself, encapsulation of theprecursor within the degradable matrix may lessen potential dustinhalation hazards for operational personnel. Furthermore, a number ofdegradable matrices are available and may be chosen to tailor thedegradation process to a particular set of wellbore conditions that maybe present. Finally, the disclosure herein is fully compatible withexisting technologies for mitigating re-precipitation of siliceousmaterials following their dissolution. Further disclosure in regard tothe foregoing follows below.

In addition to the advantages described above, the inventors recognizedthat further benefits may be realized by incorporating various types offluid loss control particulates within a treatment fluid delivering thelatent hydrofluoric acid composition to a siliceous material. The fluidloss control particulates may be co-deposited with the latenthydrofluoric acid composition in similar locations within the siliceousmaterial, or they may penetrate even deeper within a fracture network topromote treatment fluid retention within a desired portion of thesubterranean formation. The latent hydrofluoric acid composition canfurther facilitate placement of the fluid loss control particulates bypreventing their reaction with hydrofluoric acid during transport. Fluidloss control may be especially advantageous once etching has taken placewithin the fracture network to expand the fractures.

In various embodiments, treatment fluids for affecting differentialacidizing of a siliceous material are described herein. The treatmentfluids may comprise an aqueous carrier fluid, and a latent hydrofluoricacid composition present in a non-dissolved form in the aqueous carrierfluid. The latent hydrofluoric acid composition may comprise adegradable matrix and a hydrofluoric acid precursor dispersed in thedegradable matrix. The non-dissolved form of the latent hydrofluoricacid composition may comprise a solid form of the latent hydrofluoricacid composition. In some embodiments, the degradable matrix may form afull or partial coating upon the hydrofluoric acid precursor. In someembodiments, the degradable matrix may be continuous, rather than beingin the form of discrete particles.

Suitable aqueous carrier fluids may include, for example, fresh water,treated water, recycled water, ground water, flowback water, producedwater, brackish water, acidified water, salt water, seawater, brine(e.g., a saturated salt solution), or an aqueous salt solution (e.g., anon-saturated salt solution). Aqueous carrier fluids may be obtainedfrom any suitable source. Given the benefit of the present disclosure,one of ordinary skill in the art will be able to determine anappropriate aqueous carrier fluid and amount thereof for utilization inthe embodiments described herein.

In some embodiments, the aqueous carrier fluid may be chosen such thatit is substantially free of alkali metal ions. For purposes of thisdisclosure, an aqueous carrier fluid or a treatment fluid formedtherefrom will be considered to be substantially free of alkali metalions if less than about 1 wt. % alkali metal ions are present. Choice ofan aqueous carrier fluid that is substantially free of alkali metal ionsmay be desirable in order to limit re-precipitation of alkali metalaluminosilicates, fluorosilicates, and fluoroaluminates followingdissolution of a siliceous material. Other features and considerationsthat may be utilized to mitigate re-precipitation issues followingdissolution of a siliceous material are discussed further hereinbelow.

In some embodiments, an organic co-solvent may be included with anaqueous carrier fluid. Suitable organic co-solvents may be miscible withthe aqueous carrier fluid and include solvents such as, but not limitedto, glycols and alcohols. When present, the amount of the organicco-solvent may range between about 1% to about 50% by volume of thetreatment fluid. Considerations for including an organic co-solventalong with an aqueous carrier fluid may include, for example, precludingsolubility of the latent hydrofluoric acid composition.

Suitable degradable matrices and their degradation mechanisms are notbelieved to be particularly limited. For example, in variousembodiments, the degradable matrix may degrade under particular pHconditions, oxidative conditions, photolytic conditions, biologicalconditions, dissolution conditions, or the like. For purposes of thisdisclosure, dissolution of an initially insoluble material will beconsidered to constitute degradation. Particular pH conditions mayentail acidic conditions or basic conditions depending upon the chosendegradable matrix. In some embodiments, it may be advantageous for thedegradable matrix to be acid-degradable, since the degradable matrix mayundergo at least partial degradation and the hydrofluoric acid precursormay be converted into hydrofluoric acid under a single set of pHconditions. Particular acid-degradable matrices are discussedhereinbelow.

In some embodiments, the degradable matrix may comprise a degradablepolymer. Degradable polymers that may be used in conjunction with thevarious embodiments of the present disclosure include, for example,polysaccharides, proteins, polyesters (particularly aliphaticpolyesters), poly(hydroxyalkanoates), poly(□-hydroxyalkanoates),poly(ω-hydroxy alkanoates), polylactides, polyglycolides,poly(□-caprolactone)s, poly(hydroxybutyrate)s, poly(alkylenedicarboxylates), polyanhydrides, poly(hydroxy ester ether)s, poly(etherester)s, poly(ester amide)s, polycarbamates (i.e., polyurethanes),polycarbonates, poly(orthoester)s, poly(amino acid)s, poly(ethyleneoxide), polyphosphazenes, polyvinyl alcohol, methyl cellulose, ethylcellulose, carboxymethyl cellulose, carboxyethyl cellulose, acetylcellulose, hydroxyethyl cellulose, shellac, dextran, guar, xanthan,starch, a scleroglucan, a diutan, poly(vinyl pyrollidone),polyacrylamide, polyacrylic acid, poly(diallyldimethylammoniumchloride), poly(ethylene glycol), polylysine, polymethacrylamide,polymethacrylic acid, poly(vinylamine), any derivative thereof, anycopolymer thereof, any salt thereof, and any combination thereof.Copolymers may include random, block, graft, and/or star copolymers invarious embodiments.

In more particular embodiments, the degradable polymer may comprise anacid-degradable polymer. In some embodiments, a suitable acid-degradablepolymer may comprise a polylactide or an aliphatic polyester. In stillmore particular embodiments, a suitable acid-degradable polymer maycomprise polylactic acid, any derivative thereof, or any combinationthereof. The polylactic acid may be of the L-configuration, theD-configuration, or any combination thereof, and the chosenconfiguration may impact the degradation rate of the degradable matrix.Without being bound by theory or mechanism, the configuration or mixtureof configurations of the lactic acid monomers in the polylactic acid mayimpact the polymer's crystallinity, which may, in turn, affect thedegradation rate of the degradable matrix. Combinations of the L- andD-configurations may comprise a racemic mixture, or one configurationmay be present in excess over the other. The degradation rate may alsobe a function of the temperature conditions to which the polylactic acidis exposed. Polylactic acid may be especially advantageous in thecontext of the present disclosure, since it may help suppressre-precipitation of dissolved silicon compounds by at least partiallycomplexing dissolved metal ions produced upon dissolution of a siliceousmaterial.

In some embodiments, a dehydrated compound may comprise at least aportion of the degradable matrix by slowly hydrating over time andbecoming soluble, thereby exposing the hydrofluoric acid precursor in asimilar manner to that described above. Dehydrated borates representillustrative examples of dehydrated compounds that may be used in thisregard. Illustrative dehydrated borates can include, for example,anhydrous sodium tetraborate (anhydrous borax) and anhydrous boric acid.These anhydrous borates and others are only slightly soluble in water.However, upon exposure to subterranean temperatures, they can slowlyrehydrate and become considerably more soluble over a timeframe of about8 hours to about 72 hours, depending upon the temperature. In someembodiments, a dehydrated compound may be used in combination with adegradable polymer, a non-degradable polymer or any combination thereofin the degradable matrix in order to convey adequate protection to thehydrofluoric acid-generating compound and to tailor the degradationrate. For example, the polymer may protect the hydrofluoric acidprecursor from undergoing a premature reaction, and the solubilizationof the dehydrated compound may promote exposure of the hydrofluoric acidprecursor to conditions that affect its conversion to hydrofluoric acid.

In some embodiments, an oil-soluble material may comprise at least aportion of the degradable matrix by slowly dissolving over timefollowing exposure to a formation fluid, thereby exposing thehydrofluoric acid precursor in a similar manner to that described above.Suitable oil-soluble materials that may be used in conjunction with theembodiments of the present disclosure include, for example,poly(butadiene), polyisoprene, polyacrylics, polyamides, polyetherurethanes, polyester urethanes, and polyolefins (e.g., polyethylene,polypropylene, polyisobutylene, and polystyrene), any copolymer thereof,and any combination thereof.

In various embodiments, a loading of the hydrofluoric acid precursor inthe degradable matrix may range between about 1% and about 50% by weightof the latent hydrofluoric acid composition. In more specificembodiments, a loading of the hydrofluoric acid precursor may be betweenabout 5% and about 25% by weight of the latent hydrofluoric acidcomposition, or between about 5% and about 15% by weight of the latenthydrofluoric acid composition, or between about 1% and about 15% byweight of the latent hydrofluoric acid composition, or between about 1%and about 10% by weight of the latent hydrofluoric acid composition, orbetween about 5% and about 10% by weight of the latent hydrofluoric acidcomposition. A loading of the latent hydrofluoric acid composition inthe treatment fluid, in turn, may be chosen based upon the amount of thelatent hydrofluoric acid composition that needs to be deposited in agiven treatment operation.

In some embodiments, the treatment fluids of the present disclosure mayfurther comprise a plurality of fluid loss control particulates in theaqueous carrier fluid. As used herein, the term “fluid loss controlparticulates” will refer to a solid material having at least onedimension ranging between about 0.1 □m and about 500 □m in size. Thissize range may represent an equivalent spherical diameter, although thefluid loss control particulates need not necessarily be substantiallyspherical in shape. In more particular embodiments, the fluid losscontrol particulates may range between about 0.1 □mm and about 150 □m insize, or between about 1 □m and about 100 □m in size. The amount offluid loss control particulates incorporated within the aqueous carrierfluid may be adjusted to perform a desired function in a subterraneanformation, and such considerations will be familiar to one havingordinary skill in the art. For example, the resultant permeability ofthe subterranean formation and the size of the fractures within itsfracture network may dictate, at least in part, the quantity and size ofthe fluid loss control particulates to include in the treatment fluid.Other than the fluid loss control particulates and the latenthydrofluoric acid composition, the treatment fluids of the presentdisclosure may be free of other particulates, such as proppant materialsor gravel particulates. That is, the latent hydrofluoric acidcomposition may be deposited within substantially unpropped fractures invarious embodiments of the present disclosure.

In more particular embodiments, suitable fluid loss control particulatesmay comprise fly ash, or they may be formed from fly ash. As usedherein, the term “fly ash” will refer to a solid product of combustionthat rises with a flue of combustion products. Most often, the term “flyash” will refer to the fine particulates that are formed during coalcombustion, but it is to be recognized that fly ash can also be producedfrom other sources. Fly ash formed during coal combustion can compriselarge amounts of silicon dioxide and calcium oxide. Sieving or othersize-based separation techniques can optionally be performed on nativelyproduced fly ash if a specific particle size distribution is needed.

In some or other embodiments, suitable fluid loss control particulatesmay comprise a particulate material selected from the group consistingof silica flour, fly ash, mica, polymer particulates, cured resinpowders, a ceramic microbody, and a glass microbody. As used herein, theterm “silica flour” will refer to a fine particulate material comprisingsilicon dioxide and that is produced by grinding sand or a likesiliceous material. Suitable silica flours can include, for example, 325mesh or 200 mesh silica flours. Glass and ceramic microbodies mayinclude both solid and hollow three-dimensional structures.

Suitable ceramics that may be included in ceramic microbodies include,for example, silicon carbide, aluminum carbide, boron carbide, anycombination thereof, and the like. Suitable ceramic microbodies mayinclude, but are not limited to, ceramic microspheres such as N-1000 orN-1200 Zeeospheres (Zeeospheres Ceramics, LLC, which contain asilicon-aluminum ceramic and have 95% of their particles less than 150microns in size). Other commercially available ceramic microspheres mayalso be suitable.

Suitable glass microbodies may include glass microspheres such as, butnot limited, to HGS10000 and HGS18000 (3M Corporation), which have95^(th) percentile diameters of 65 and 60 microns, respectively, andtrue density values of 0.63 g/cm³. Other commercially available glassmicrospheres may also be suitable.

In principle, any hydrofluoric acid precursor can be incorporated withinthe degradable matrix of the latent hydrofluoric acid composition. Inthis regard, hydrofluoric acid precursors that may be utilized in thevarious embodiments of the present disclosure include substances suchas, for example, fluoroboric acid, fluorosulfuric acid,hexafluorophosphoric acid, hexafluoroantimonic acid, difluorophosphoricacid, hexafluorosilicic acid, potassium hydrogen difluoride, sodiumhydrogen difluoride, polyvinylammonium fluoride, polyvinylpyridiniumfluoride, pyridinium fluoride, imidazolium fluoride, ammonium fluoride,tetrafluoroborate salts, hexafluoroantimonate salts, hexafluorophosphatesalts, bifluoride salts (e.g., ammonium bifluoride), perfluorinatedorganic compounds, titanium fluorides (e.g., TiF₄ and TiF₆ ²⁻), cesiumfluoride, boron trifluoride and various boron trifluoride complexes.

In more particular embodiments of the present disclosure, thehydrofluoric acid precursor may comprise a solid material, such as anysolid hydrofluoric acid precursor(s) selected from the listing above.Solid hydrofluoric acid precursors may be readily dispersed in thedegradable matrix of the latent hydrofluoric acid composition and besubstantially protected from undergoing a premature reaction to formhydrofluoric acid. Moreover, under most circumstances, the rheologicaland buoyancy properties of the latent hydrofluoric acid composition maybe determined in substantial part by the properties of the degradablematrix itself in such embodiments, rather than by the hydrofluoric acidprecursor. Particularly suitable solid hydrofluoric acid precursors mayinclude, for example, ammonium bifluoride or ammonium fluoride, sincethese hydrofluoric acid precursors are readily soluble in aqueous fluidsand quickly generate hydrofluoric acid upon exposure to an aqueous acid.In addition, these hydrofluoric acid precursors do not contain anyelements that represent significant environmental concerns or could leadto potential secondary formation damage.

In alternative embodiments, the latent hydrofluoric acid composition maycomprise a liquid hydrofluoric acid precursor or a gaseous hydrofluoricacid precursor. Protection of both of these types of hydrofluoric acidprecursors by the degradable matrix may be more difficult than for solidhydrofluoric acid precursors, since liquid or gaseous hydrofluoric acidprecursors may be more difficult to isolate from conditions that wouldotherwise promote their solubilization and/or conversion intohydrofluoric acid.

In some embodiments, the treatment fluid may be foamed in order topromote delivery of the latent hydrofluoric acid composition and/orfluid loss control particulates within a wellbore. Foaming the treatmentfluid may minimize settling or loss of these materials at an undesiredlocation. Additionally, foaming the treatment fluid may allow lowertreatment fluid volumes to be utilized than would otherwise be possible.

In additional embodiments, the treatment fluids described herein mayfurther comprise any number of additives that are commonly used indownhole operations including, for example, silica scale controladditives, chelating agents, surfactants, gel stabilizers,anti-oxidants, polymer degradation prevention additives, relativepermeability modifiers, scale inhibitors, foaming agents, defoamingagents, antifoaming agents, emulsifying agents, de-emulsifying agents,iron control agents, particulate diverters, salts, acids, fluid losscontrol additives, gas, catalysts, clay control agents, dispersants,flocculants, scavengers (e.g., H₂S scavengers, CO₂ scavengers or O₂scavengers), gelling agents, lubricants, friction reducers, bridgingagents, viscosifiers, weighting agents, solubilizers, pH control agents(e.g., buffers), hydrate inhibitors, consolidating agents, bactericides,catalysts, clay stabilizers, breakers, delayed release breakers, and thelike. Any combination of these additives may be used as well.Particularly suitable additives for inclusion in the treatment fluidsmay include those which can mitigate re-precipitation followingdissolution of a siliceous material, such as silica scale controladditives, chelating agents, and the like. Given the benefit of thepresent disclosure, one having ordinary skill in the art will be able toformulate a treatment fluid having properties suitable for a givenapplication.

Methods for acidizing a subterranean formation using the latenthydrofluoric acid compositions of the present disclosure are alsocontemplated herein. When used during an acidizing operation, the latenthydrofluoric acid compositions may be deposited or placed upon a portionof a siliceous material, such that differential dissolution of thesiliceous material takes place. Additional disclosure in this regardfollows below.

In some embodiments, methods of the present disclosure may comprise:providing a latent hydrofluoric acid composition comprising a degradablematrix, and a hydrofluoric acid precursor dispersed in the degradablematrix; introducing a first treatment fluid containing the latenthydrofluoric acid composition in a non-dissolved form into a wellborepenetrating a subterranean formation comprising a siliceous material;differentially depositing the latent hydrofluoric acid composition upona portion of the siliceous material in one or more locations; degradingat least a portion of the degradable matrix, thereby exposing at least aportion of the hydrofluoric acid precursor; converting the exposedhydrofluoric acid precursor into hydrofluoric acid; and reacting thehydrofluoric acid with the siliceous material in at least a portion ofthe one or more locations where the latent hydrofluoric acid compositionwas deposited.

In some embodiments of the present disclosure, the siliceous materialmay be present in a reservoir comprising a mineral such as shale,sandstone, mudstone or any combination thereof. In some embodiments, thesubterranean formation may comprise a low-permeability variant of theseminerals or another type of siliceous mineral. As used herein, the term“low-permeability” will refer to a mineral whose native permeability isabout 1 millidarcy or below.

In various embodiments, differentially depositing the latenthydrofluoric acid composition upon a portion of the siliceous materialmay comprise non-uniformly placing the latent hydrofluoric acidcomposition on or within the siliceous material. In more particularembodiments, a non-uniform placement of the latent hydrofluoric acidcomposition may be such that the latent hydrofluoric acid composition isdeposited within a fracture network defined in the siliceous material.The fracture network in which the latent hydrofluoric acid compositionis deposited may comprise the naturally occurring conduits associatedwith the native permeability of the siliceous material in someembodiments. In other embodiments, the naturally occurring conduits of afracture network may be extended or expanded in a fracturing operation,and the latent hydrofluoric acid composition may be deposited therein.In still other embodiments, the conduits within the fracture network maybe generated de novo in a fracturing operation, with the latenthydrofluoric acid composition being deposited in the newly generatedfractures thereafter.

Facile differential deposition of the latent hydrofluoric acidcomposition upon the siliceous material may be realized by introducingthe first treatment fluid and the latent hydrofluoric acid compositioncontained therein into the wellbore at or above a fracture gradientpressure of the siliceous material. Under such conditions, any nativelypresent conduits of an existing fracture network in the siliceousmaterial can at least temporarily expand, thereby allowing the latenthydrofluoric acid composition entry thereto. Any newly generatedfractures in the siliceous material may similarly receive the latenthydrofluoric acid composition from the wellbore. Upon removing thehydraulic fracturing pressure, the expanded fractures may at leastpartially close, thereby trapping the latent hydrofluoric acidcomposition within the fractures or at least slowing its diffusion backinto the wellbore. In some embodiments, any residual latent hydrofluoricacid composition remaining in the wellbore may be removed in anoverflush, thereby further increasing the differential nature of thedeposition process. When present in the first treatment fluid, aplurality of fluid loss control particulates may be deposited similarlywithin the fracture network in combination with the latent hydrofluoricacid composition.

In alternative embodiments, a pad fluid may precede the first treatmentfluid and also be introduced to the wellbore at or above the fracturegradient pressure. As used herein, the term “pad fluid” will refer to aproppant-free treatment fluid that is introduced to a wellbore prior toa larger volume of fracturing fluid containing proppant particulates ora similar type of treatment fluid containing particulates. Oncefractures in the siliceous material have been created or extended withthe pad fluid, the latent hydrofluoric acid composition of the firsttreatment fluid may then become localized within the fractures asdescribed hereinabove.

After being differentially deposited upon the siliceous material,hydrofluoric acid may be generated from the latent hydrofluoric acidcomposition to provide differential etching of the siliceous material.The differential etching may define or modify flow pathways throughoutthe siliceous material and increase its effective permeability, muchlike that seen during acidizing of a carbonate material. Following atleast partial degradation of the degradable matrix and exposure of thehydrofluoric acid precursor to a reactive environment, the hydrofluoricacid precursor may react readily to generate hydrofluoric acid locallywhere it is deposited upon the portions of the siliceous material.Accordingly, non-uniform dissolution of the siliceous material may berealized due to the localization of the hydrofluoric acid. Generation ofhydrofluoric acid from the latent hydrofluoric acid composition maycomprise first degrading at least a portion of the degradable matrix toexpose the hydrofluoric acid precursor to a reactive environment (e.g.,an acid capable of converting the hydrofluoric acid precursor intohydrofluoric acid).

As discussed above, in some embodiments, the degradable matrix maycomprise an acid-degradable matrix, such as an acid-degradable polymer.Specific examples of acid-degradable polymers are provided above.Accordingly, in certain embodiments, degrading the degradable matrix maycomprise contacting an acid-degradable polymer in the degradable matrixwith an aqueous acid. An acid-generating compound may be used similarlyin this regard. The aqueous acid may comprise any organic or mineralacid that is present in a concentration suitable to degrade theacid-degradable polymer at a chosen rate.

The methods of the present disclosure allow considerable flexibility tobe realized in how an acid is contacted with an acid-degradable polymeror other acid-degradable matrix. In some embodiments, the firsttreatment fluid may further comprise an acid, an acid-generatingcompound or any combination thereof, with the acid or generated acidpromoting degradation of the acid-degradable polymer and ensuingconversion of the exposed hydrofluoric acid precursor into hydrofluoricacid. Although it might seem counterintuitive to include an acid sourcein the same treatment fluid with an acid-degradable polymer or otheracid-degradable matrix, the acid-degradable polymer or matrix maypersist long enough after being combined with the acid such that thelatent hydrofluoric acid composition can still be delivered downholeeffectively. The acid concentration and the particular acid-degradablepolymer, for example, may be chosen to attain a suitable degradationrate for delivery under a particular set of downhole and pH conditions.Among other factors, the temperature of the subterranean formation maybe considered when assessing the degradation rate under a particular setof conditions. Inclusion of an acid or an acid-generating compound inthe first treatment fluid in combination with the latent hydrofluoricacid composition may limit the number of treatment stages needing to beperformed, thereby helping to limit costs of the acidizing operation.

In alternative embodiments, methods of the present disclosure mayfurther comprise introducing a second treatment fluid comprising anacid, an acid-generating compound, or any combination thereof into thewellbore after the latent hydrofluoric acid composition has beendifferentially deposited. Utilization of a second treatment fluid toinduce degradation of the degradable matrix may be desirable when a morelengthy delay is needed for releasing hydrofluoric acid than can berealized by including an acid or acid-generating compound in the firsttreatment fluid in combination with the latent hydrofluoric acidcomposition.

Particular examples of acids suitable for inclusion in the firsttreatment fluid and/or the second treatment fluid may include, but arenot limited to, hydrochloric acid, hydrobromic acid, formic acid, aceticacid, chloroacetic acid, dichloroacetic acid, trichloroacetic acid,fluoroacetic acid, difluoroacetic acid, trifluoroacetic acid,methanesulfonic acid, citric acid, maleic acid, glycolic acid, lacticacid, malic acid, oxalic acid, the like, and any combination thereof.Examples of suitable acid-generating compounds may include, but are notlimited to, esters, aliphatic polyesters, orthoesters,poly(orthoesters), poly(lactides), poly(glycolides),poly(□-caprolactones), poly(hydroxybutyrates), poly(anhydrides),ethylene glycol monoformate, ethylene glycol diformate, diethyleneglycol diformate, glyceryl monoformate, glyceryl diformate, glyceryltriformate, triethylene glycol diformate, formate esters ofpentaerythritol, the like, any derivative thereof, and any combinationthereof.

The particular acid-degradable material comprising the degradable matrixmay dictate the chosen acid or acid-generating compound and itsconcentration. Mineral acids may be present in the treatment fluids inan amount ranging between about 1% and about 20% of the treatment fluidby weight, or in an amount ranging between about 1% and about 15% of thetreatment fluid by weight, or in an amount ranging between about 5% andabout 10% of the treatment fluid by weight. Higher mineral acidconcentrations may be used as well. Since organic acids are generallyless acidic than are mineral acids, the organic acids may comprise up toabout 25% of a treatment fluid by weight, particularly between about 1%and about 25% of the treatment fluid by weight, or between about 10% andabout 20% of the treatment fluid by weight. Acid-generating compoundsmay be used to produce acids at similar concentration values. Thetreatment fluids can have a pH value of about 4 or lower, or about 3.5or lower, or about 3 or lower, or about 2.5 or lower, or about 2 orlower, or about 1.5 or lower, or about 1 or lower. In more particularembodiments, the pH may range between about 0 and about 4, or betweenabout 1 and about 4, or between about 1 and about 3, or between about 2and about 4.

Accordingly, in other various embodiments of the present disclosure,methods for differentially acidizing a siliceous material may comprise:introducing a first treatment fluid containing a latent hydrofluoricacid composition into a wellbore penetrating a subterranean formationcomprising a siliceous material, the latent hydrofluoric acidcomposition being present in a non-dissolved form in the first treatmentfluid and comprising an acid-degradable matrix, and a hydrofluoric acidprecursor dispersed in the acid-degradable matrix; depositing at least aportion of the latent hydrofluoric acid composition within a fracturenetwork defined in the siliceous material; contacting the latenthydrofluoric acid composition with an acid, thereby degrading at least aportion of the acid-degradable matrix, exposing at least a portion ofthe hydrofluoric acid precursor, and converting the exposed hydrofluoricacid precursor into hydrofluoric acid; and reacting the hydrofluoricacid within the fracture network of the siliceous material to increase apermeability of the subterranean formation.

As one of ordinary skill in the art will recognize and as referenced inbrief above, various issues with re-precipitation can be encountered inthe course of acidizing a siliceous material. Without limitation, issuesthat can be encountered include re-precipitation of siliceous compoundsonce the solubility limit of dissolved silicon has been exceeded,formation of highly insoluble alkali metal fluorosilicates or alkalimetal fluoroaluminates in the presence of alkali metal ions, formationof calcium fluoride, and any combination thereof. Depending on theactual conditions present in a given subterranean formation, aparticular re-precipitation pathway may be predominant. Illustrativestrategies to address these precipitation issues are discussed in briefhereinafter, each of which is compatible for use in conjunction with thelatent hydrofluoric acid compositions described herein. Otherprecipitation-control strategies may also be appropriate and compatiblewith the latent hydrofluoric acid composition, and the listed strategiesshould be considered to be non-limiting examples of those that may beemployed.

In some embodiments, a silica scale control additive maybe used inconjunction with the latent hydrofluoric acid composition. As usedherein, the term “silica scale control additive” will refer to asubstance that limits deposition of amorphous, gelatinous and/orcolloidal silica that leads to silica scale buildup. Illustrative silicascale control additives that may be used in this regard include, but arenot limited to, polyaminoamide dendrimers, polyethyleneimine,carboxymethylinulin, polyacrylates, phosphonates, aminocarboxylic acids,polyaminocarboxylic acids, and ortho-dihydroxybenzene compounds relatedto tannic acid. When used, a silica scale control additive may bepresent in the first treatment fluid in combination with the latenthydrofluoric acid composition or in a treatment fluid introduced to thewellbore separately from the latent hydrofluoric acid composition.

In many instances, a carbonate material may be present in conjunctionwith a siliceous material in a subterranean formation. For example,sandstone deposits may contain about 1% to about 35% carbonates inaddition to the predominant siliceous material. Upon dissolution, thecarbonate material can provide metal ions that may lead toprecipitation, either by themselves or in the presence of fluoride ionsfrom hydrofluoric acid. For example, calcium ions can react readily withfluoride ions to form highly insoluble and damaging calcium fluoride.Aluminum ions resulting from dissolution of aluminosilicates can alsorepresent a troubling source of precipitation, particularly in thepresence of alkali metal ions.

Accordingly, in some embodiments, a chelating agent may be used inconjunction with the latent hydrofluoric acid composition. The chelatingagent may complex metal ions and render them inactive such that they areno longer able to react to form insoluble compounds. As used herein, theterms “complex,” “complexing,” “complexation” and other grammaticalvariants thereof will refer to the formation of a metal-ligand bond.Although complexation of a metal ion may involve a chelation process insome embodiments, complexation is not deemed to be limited in thismanner. When used, a chelating agent may be present in the firsttreatment fluid in combination with the latent hydrofluoric acidcomposition or in a treatment fluid introduced to the wellboreseparately from the latent hydrofluoric acid composition.Aminopolycarboxylic acid chelating agents may be particularlyadvantageous chelating agents for use in the embodiments disclosedherein.

In other various embodiments, systems configured for delivering atreatment fluid of the present disclosure to a downhole location aredescribed herein. In various embodiments, the systems can comprise apump fluidly coupled to a tubular, the tubular containing a treatmentfluid comprising an aqueous carrier fluid, and a latent hydrofluoricacid composition present in a non-dissolved form in the aqueous carrierfluid. The latent hydrofluoric acid composition may comprise adegradable matrix and a hydrofluoric acid precursor dispersed in thedegradable matrix.

The pump may be a high pressure pump in some embodiments. As usedherein, the term “high pressure pump” will refer to a pump that iscapable of delivering a fluid downhole at a pressure of about 1000 psior greater. A high pressure pump may be used when it is desired tointroduce a treatment fluid of the present disclosure to a subterraneanformation at or above a fracture gradient of the subterranean formation,but it may also be used in cases where fracturing is not desired. Thetreatment fluids described herein may be introduced with a high pressurepump, or they may be introduced following a treatment fluid that wasintroduced with a high pressure pump. In some embodiments, the highpressure pump may be capable of fluidly conveying particulate matterinto the subterranean formation. Suitable high pressure pumps will beknown to one having ordinary skill in the art and may include, but arenot limited to, floating piston pumps and positive displacement pumps.

In other embodiments, the pump may be a low pressure pump. As usedherein, the term “low pressure pump” will refer to a pump that operatesat a pressure of about 1000 psi or less. In some embodiments, a lowpressure pump may be fluidly coupled to a high pressure pump that isfluidly coupled to the tubular. That is, in such embodiments, the lowpressure pump may be configured to convey the treatment fluid to thehigh pressure pump. In such embodiments, the low pressure pump may “stepup” the pressure of a treatment fluid before it reaches the highpressure pump. Alternately, the low pressure pump may be used todirectly introduce the treatment fluid to the subterranean formation.

In some embodiments, the systems described herein can further comprise amixing tank that is upstream of the pump and in which the latenthydrofluoric acid composition is formulated with a carrier fluid. Invarious embodiments, the pump (e.g., a low pressure pump, a highpressure pump, or a combination thereof) may convey the treatment fluidfrom the mixing tank or other source of the treatment fluid to thetubular. In other embodiments, however, the treatment fluid can beformulated offsite and transported to a worksite, in which case thetreatment fluid may be introduced to the tubular via the pump directlyfrom its shipping container (e.g., a truck, a railcar, a barge, or thelike) or from a transport pipeline. In either case, the treatment fluidmay be drawn into the pump, elevated to an appropriate pressure, andthen introduced into the tubular for delivery downhole.

FIG. 1 shows an illustrative schematic of a system that can delivertreatment fluids of the present disclosure to a downhole location,according to one or more embodiments. It should be noted that while FIG.1 generally depicts a land-based system, it is to be recognized thatlike systems may be operated in subsea locations as well. For example,the treatment fluid may be delivered to the downhole location of asubsea wellbore using a subsea riser structure. As depicted in FIG. 1,system 1 may include mixing tank 10, in which a treatment fluid of thepresent disclosure may be formulated. The treatment fluid may beconveyed via line 12 to wellhead 14, where the treatment fluid enterstubular 16, tubular 16 extending from wellhead 14 into subterraneanformation 18. Tubular 16 may include orifices that allow the treatmentfluid to enter into the wellbore. Pump 20 may be configured to raise thepressure of the treatment fluid to a desired degree before itsintroduction into tubular 16. It is to be recognized that system 1 ismerely exemplary in nature and various additional components may bepresent that have not necessarily been depicted in FIG. 1 in theinterest of clarity. Non-limiting additional components that may bepresent include, but are not limited to, supply hoppers, valves,condensers, adapters, joints, gauges, sensors, compressors, pressurecontrollers, pressure sensors, flow rate controllers, flow rate sensors,temperature sensors, and the like.

Although not depicted in FIG. 1, the treatment fluid may, in someembodiments, flow back to wellhead 14 and exit subterranean formation18. In some embodiments, the treatment fluid that has flowed back towellhead 14 may subsequently be recovered and recirculated tosubterranean formation 18. In other embodiments, the treatment fluid mayflow back to wellhead 14 in a produced hydrocarbon fluid fromsubterranean formation 18.

It is also to be recognized that the disclosed treatment fluids may alsodirectly or indirectly affect the various downhole equipment and toolsthat may come into contact with the treatment fluids during operation.Such equipment and tools may include, but are not limited to, wellborecasing, wellbore liner, completion string, insert strings, drill string,coiled tubing, slickline, wireline, drill pipe, drill collars, mudmotors, downhole motors and/or pumps, surface-mounted motors and/orpumps, centralizers, turbolizers, scratchers, floats (e.g., shoes,collars, valves, etc.), logging tools and related telemetry equipment,actuators (e.g., electromechanical devices, hydromechanical devices,etc.), sliding sleeves, production sleeves, plugs, screens, filters,flow control devices (e.g., inflow control devices, autonomous inflowcontrol devices, outflow control devices, etc.), couplings (e.g.,electro-hydraulic wet connect, dry connect, inductive coupler, etc.),control lines (e.g., electrical, fiber optic, hydraulic, etc.),surveillance lines, drill bits and reamers, sensors or distributedsensors, downhole heat exchangers, valves and corresponding actuationdevices, tool seals, packers, cement plugs, bridge plugs, and otherwellbore isolation devices, or components, and the like. Any of thesecomponents may be included in the systems generally described above anddepicted in FIG. 1.

Embodiments disclosed herein include:

A. Methods for acidizing a siliceous material. The methods comprise:providing a latent hydrofluoric acid composition comprising a degradablematrix, and a hydrofluoric acid precursor dispersed in the degradablematrix; introducing a first treatment fluid containing the latenthydrofluoric acid composition in a non-dissolved form into a wellborepenetrating a subterranean formation comprising a siliceous material;differentially depositing the latent hydrofluoric acid composition upona portion of the siliceous material in one or more locations; degradingat least a portion of the degradable matrix, thereby exposing at least aportion of the hydrofluoric acid precursor; converting the exposedhydrofluoric acid precursor into hydrofluoric acid; and reacting thehydrofluoric acid with the siliceous material in at least a portion ofthe one or more locations where the latent hydrofluoric acid compositionwas deposited.

B. Methods for acidizing a siliceous material. The methods comprise:introducing a first treatment fluid containing a latent hydrofluoricacid composition into a wellbore penetrating a subterranean formationcomprising a siliceous material, the latent hydrofluoric acidcomposition being present in a non-dissolved form in the first treatmentfluid and comprising an acid-degradable matrix, and a hydrofluoric acidprecursor dispersed in the acid-degradable matrix; depositing at least aportion of the latent hydrofluoric acid composition within a fracturenetwork defined in the siliceous material; contacting the latenthydrofluoric acid composition with an acid, thereby degrading at least aportion of the acid-degradable matrix, exposing at least a portion ofthe hydrofluoric acid precursor, and converting the exposed hydrofluoricacid precursor into hydrofluoric acid; and reacting the hydrofluoricacid within the fracture network of the siliceous material to increase apermeability of the subterranean formation.

C. Treatment fluids comprising a latent hydrofluoric acid composition.The treatment fluids comprise: an aqueous carrier fluid; and a latenthydrofluoric acid composition present in a non-dissolved form in theaqueous carrier fluid, the latent hydrofluoric acid compositioncomprising a degradable matrix, and a hydrofluoric acid precursordispersed in the degradable matrix.

D. Systems for introducing a latent hydrofluoric acid composition into awellbore. The systems comprise: a pump fluidly coupled to a tubular, thetubular containing a treatment fluid comprising an aqueous carrierfluid, and a latent hydrofluoric acid composition present in anon-dissolved form in the aqueous carrier fluid, the latent hydrofluoricacid composition comprising a degradable matrix, and a hydrofluoric acidprecursor dispersed in the degradable matrix.

Each of embodiments A-D may have one or more of the following additionalelements in any combination:

Element 1: wherein the degradable matrix is acid-degradable.

Element 2: wherein the degradable matrix comprises an acid-degradablepolymer.

Element 3: wherein the acid-degradable polymer comprises polylacticacid, any derivative thereof, or any combination thereof.

Element 4: wherein the first treatment fluid further comprises an acid,an acid-generating compound, or any combination thereof.

Element 5: wherein the method further comprises introducing a secondtreatment fluid comprising an acid, an acid-generating compound, or anycombination thereof into the wellbore after differentially depositingthe latent hydrofluoric acid composition.

Element 6: wherein the hydrofluoric acid precursor comprises a solidmaterial.

Element 7: wherein the siliceous material is present in a reservoircomprising a mineral selected from the group consisting of shale,sandstone, mudstone, and any combination thereof.

Element 8: wherein the latent hydrofluoric acid composition is depositedwithin a fracture network defined in the siliceous material.

Element 9: wherein the first treatment fluid is introduced into thewellbore at or above a fracture gradient pressure of the siliceousmaterial.

Element 10: wherein the first treatment fluid further comprises aplurality of fluid loss control particulates, the plurality of fluidloss control particulates being deposited within the fracture network incombination with the latent hydrofluoric acid composition.

Element 11: wherein the first treatment fluid further comprises theacid, an acid-generating compound, or any combination thereof.

Element 12: wherein the method further comprises introducing a secondtreatment fluid comprising the acid, an acid-generating compound, or anycombination thereof into the wellbore after depositing the latenthydrofluoric acid composition within the fracture network.

Element 13: wherein the first treatment fluid further comprises aplurality of fluid loss control particulates, the plurality of fluidloss control particulates being deposited within the fracture network incombination with the latent hydrofluoric acid composition.

Element 14: wherein the treatment fluid further comprises a plurality offluid loss control particulates in the aqueous carrier fluid.

By way of non-limiting example, exemplary combinations applicable to A-Dinclude:

The method of A in combination with elements 2 and 4.

The method of A in combination with elements 2 and 5.

The method of A in combination with elements 2 and 6.

The method of A in combination with elements 1 and 7.

The method of A in combination with elements 4 and 7.

The method of A in combination with elements 5 and 7.

The method of A in combination with elements 3 and 4.

The method of A in combination with elements 3 and 5.

The method of A in combination with elements 6 and 10.

The method of A in combination with elements 8 and 10.

The method of A in combination with elements 7 and 8.

The method of A in combination with elements 8 and 9.

The method of A in combination with elements 1 and 10.

The method of A in combination with elements 3 and 10.

The method of A in combination with elements 3, 4 and 6.

The method of A in combination with elements 3, 5 and 6.

The method of B in combination with elements 2 and 3.

The method of B in combination with elements 2 and 4.

The method of B in combination with elements 2 and 5.

The method of B in combination with elements 7 and 11.

The method of B in combination with elements 7 and 12.

The method of B in combination with elements 3 and 11.

The method of B in combination with elements 3 and 12.

The method of B in combination with elements 3 and 10.

The method of B in combination with elements 6 and 10.

The method of B in combination with elements 9 and 10.

The treatment fluid of C or the system of D in combination with elements1 and 2.

The treatment fluid of C or the system of D in combination with elements2 and 3.

The treatment fluid of C or the system of D in combination with elements1 and 6.

The treatment fluid of C or the system of D in combination with elements2 and 6.

The treatment fluid of C or the system of D in combination with elements4 and 10.

The treatment fluid of C or the system of D in combination with elements6 and 10.

To facilitate a better understanding of the embodiments of the presentdisclosure, the following examples of preferred or representativeembodiments are given. In no way should the following examples be readto limit, or to define, the scope of the disclosure.

EXAMPLES Example 1: Treatment of a Shale Core with a Latent HydrofluoricAcid Composition

A Marcellus shale core sample was cut in two halves, and each half waspolished to a smooth finish. Control: Polylactic acid (PLA) wassandwiched between the two halves of the core sample. The two halveswere then bound tightly together to simulate a fracture, and the boundcore plus PLA was placed in a 15% HCl solution at 200° F. for 16 hours.No etching or pitting of the core sample was observed following theheating period. Experimental: A latent hydrofluoric acid composition wasprepared by mixing a 1:1 weight ratio of PLA and ammonium bifluoride inmethylene chloride. The thick slurry was then placed in a “pattern” upona surface of the split core, and the methylene chloride was allowed toevaporate. The two halves of the split core were then bound together tosimulate a fracture. FIG. 2 shows an image of the latent hydrofluoricacid composition deposited in a pattern on the split core. The “pattern”was maintained upon evaporation of the methylene chloride and afterbinding the two core halves together. As in the control sample, the twohalves of the split core sample were then bound together to constrainthe latent hydrofluoric acid composition within a simulated fracture.The bound core plus the latent hydrofluoric acid composition wassimilarly placed in 15% HCl at 200° F. overnight. Unlike the controlsample, visually distinct pitting and etching was observed upon theportions of the core face where the latent hydrofluoric acid compositionwas initially present. FIG. 3 shows an illustrative profilometry plotfollowing differential etching of the split core. The locations of moreintense grayscale color variation indicate where the most etchingoccurred. The etching regions closely matched the “pattern” of thedeposited latent hydrofluoric acid composition (FIG. 2).

Unless otherwise indicated, all numbers expressing quantities ofingredients, properties such as molecular weight, reaction conditions,and so forth used in the present specification and associated claims areto be understood as being modified in all instances by the term “about.”Accordingly, unless indicated to the contrary, the numerical parametersset forth in the specification and attached claims are approximationsthat may vary depending upon the desired properties sought to beobtained by the embodiments of the present disclosure. At the veryleast, and not as an attempt to limit the application of the doctrine ofequivalents to the scope of the claim, each numerical parameter shouldat least be construed in light of the number of reported significantdigits and by applying ordinary rounding techniques.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present disclosure. The disclosureillustratively disclosed herein suitably may be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range are specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces.

The invention claimed is:
 1. A treatment fluid comprising: an aqueouscarrier fluid; and a latent hydrofluoric acid composition present in anon-dissolved form in the aqueous carrier fluid, the latent hydrofluoricacid composition comprising a degradable matrix and a hydrofluoric acidprecursor dispersed in the degradable matrix.
 2. The treatment fluid ofclaim 1, further comprising a plurality of fluid loss controlparticulates.
 3. The treatment fluid of claim 2, wherein the fluid losscontrol particulate has at least one dimension ranging between about 0.1μm to about 500 μm.
 4. The treatment fluid of claim 1, wherein thedegradable matrix comprises a degradable polymer selected from the groupconsisting of polysaccharides, proteins, aliphatic polyesters,poly(hydroxyalkanoates), poly(β-hydroxyalkanoates), poly(ω-hydroxyalkanoates), polylactides, polyglycolides, poly(ϵ-caprolactone)s,poly(hydroxybutyrate)s, poly(alkylene dicarboxylates), polyanhydrides,poly(hydroxy ester ether)s, poly(ether ester)s, poly(ester amide)s,polycarbamates (i.e., polyurethanes), polycarbonates, poly(orthoester)s,poly(amino acid)s, poly(ethylene oxide), polyphosphazenes, polyvinylalcohol, methyl cellulose, ethyl cellulose, carboxymethyl cellulose,carboxyethyl cellulose, acetyl cellulose, hydroxyethyl cellulose,shellac, dextran, guar, xanthan, starch, a scleroglucan, a diutan,poly(vinyl pyrollidone), polyacrylamide, polyacrylic acid,poly(diallyldimethylammonium chloride), poly(ethylene glycol),polylysine, polymethacrylamide, polymethacrylic acid, poly(vinylamine),any derivative thereof, any copolymer thereof, any salt thereof, and anycombination thereof.
 5. The treatment fluid of claim 1, wherein thedegradable matrix is acid-degradable.
 6. The treatment fluid of claim 1,wherein the degradable matrix comprises an acid-degradable polymer. 7.The treatment fluid of claim 6, wherein the acid-degradable polymercomprises polylactic acid, any derivative thereof, or any combinationthereof.
 8. The treatment fluid of claim 1, wherein the degradablematrix undergoes degradation to expose at least a portion of thehydrofluoric acid precursor to reactive conditions.
 9. The treatmentfluid of claim 1, wherein the hydrofluoric acid precursor comprises asolid material.
 10. The treatment fluid of claim 1, wherein thehydrofluoric precursor is loaded in the degradable matrix in an amountof about 1% to about 50% by weight of the latent hydrofluoric acidcomposition.
 11. The treatment fluid of claim 1, wherein thehydrofluoric acid precursor is selected from the group consisting of:fluoroboric acid, fluorosulfuric acid, hexafluorophosphoric acid,hexafluoroantimonic acid, difluorophosphoric acid, hexafluorosilicicacid, potassium hydrogen difluoride, sodium hydrogen difluoride,polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridiniumfluoride, imidazolium fluoride, ammonium fluoride, tetrafluoroboratesalts, hexafluoroantimonate salts, hexafluorophosphate salts, bifluoridesalts, perfluorinated organic compounds, TiF₄, TiFs₆ ²⁻, cesiumfluoride, boron trifluoride, boron trifluoride complexes, orcombinations thereof.
 12. A treatment fluid comprising: an aqueouscarrier fluid; and a latent hydrofluoric acid composition present in anon-dissolved form in the aqueous carrier fluid, the latent hydrofluoricacid composition comprising a degradable matrix, a hydrofluoric acidprecursor dispersed in the degradable matrix, and a plurality of fluidloss control particulates.
 13. The treatment fluid of claim 12, whereinthe hydrofluoric acid precursor is selected from the group consistingof: fluoroboric acid, fluorosulfuric acid, hexafluorophosphoric acid,hexafluoroantimonic acid, difluorophosphoric acid, hexafluorosilicicacid, potassium hydrogen difluoride, sodium hydrogen difluoride,polyvinylammonium fluoride, polyvinylpyridinium fluoride, pyridiniumfluoride, imidazolium fluoride, ammonium fluoride, tetrafluoroboratesalts, hexafluoroantimonate salts, hexafluorophosphate salts, bifluoridesalts, perfluorinated organic compounds, TiF₄, TiF₆ ²⁻, cesium fluoride,boron trifluoride, boron trifluoride complexes, or combinations thereof.14. The treatment fluid of claim 12, wherein the fluid loss controlparticulate has at least one dimension ranging between about 0.1 μm toabout 500 μm.
 15. The treatment fluid of claim 12, wherein thedegradable matrix is acid-degradable.
 16. The treatment fluid of claim12, wherein the degradable matrix comprises a degradable polymer. 17.The treatment fluid of claim 16, wherein the degradable polymer isselected from the group consisting of polysaccharides, proteins,aliphatic polyesters, poly(hydroxyalkanoates),poly(β-hydroxyalkanoates), poly(ω-hydroxy alkanoates), polylactides,polyglycolides, poly(ϵ-caprolactone)s, poly(hydroxybutyrate)s,poly(alkylene dicarboxylates), polyanhydrides, poly(hydroxy esterether)s, poly(ether ester)s, poly(ester amide)s, polycarbamates (i.e.,polyurethanes), polycarbonates, poly(orthoester)s, poly(amino acid)s,poly(ethylene oxide), polyphosphazenes, polyvinyl alcohol, methylcellulose, ethyl cellulose, carboxymethyl cellulose, carboxyethylcellulose, acetyl cellulose, hydroxyethyl cellulose, shellac, dextran,guar, xanthan, starch, a scleroglucan, a diutan, poly(vinylpyrollidone), polyacrylamide, polyacrylic acid,poly(diallyldimethylammonium chloride), poly(ethylene glycol),polylysine, polymethacrylamide, polymethacrylic acid, poly(vinylamine),any derivative thereof, any copolymer thereof, any salt thereof, and anycombination thereof.
 18. The treatment fluid of claim 12, wherein thedegradable matrix comprises an acid-degradable polymer.
 19. Thetreatment fluid of claim 18, wherein the acid-degradable polymercomprises polylactic acid, any derivative thereof, or any combinationthereof.
 20. A system comprising: a pump fluidly coupled to a tubular,the tubular containing a treatment fluid comprising an aqueous carrierfluid, and a latent hydrofluoric acid composition present in anon-dissolved form in the aqueous carrier fluid, the latent hydrofluoricacid composition comprising a degradable matrix, and a hydrofluoric acidprecursor dispersed in the degradable matrix.